Downhole motors are used in the hydrocarbon industry to apply mechanical power at a downhole location to a drill bit in oil and/or gas wells for drilling applications. The downhole motor, sometimes referred to as a mud motor, is positioned at the bottom of a drillstring and coupled via an output shaft with a drill bit. Drilling fluid, sometimes referred to as drilling mud or simply mud, is pumped down the drillstring and through the downhole motor. The downhole motor uses the force of the pumped/flowing drilling fluid to produce a mechanical output, a rotation of the output shaft and, in turn, the drill bit.
Although there are different types of downhole/mud motors, the most commonly used type today is a positive displacement motor which uses an elongated, helically-shaped rotor within a corresponding helically shaped stator. The flow of drilling fluid or mud between the stator and rotor causes the rotor to orbit within the stator eccentrically about the longitudinal axis of the stator. The rotor itself rotates about its longitudinal axis and also orbits around the central longitudinal axis of the stator. This eccentric orbit and rotation of the rotor is transferred by a suitable transmission assembly, such as a universal joint assembly, to produce a concentric rotation for the output shaft.
Other types of downhole motors include turbines in which a rotor/shaft equipped with vanes is caused to rotate by a fluid—a liquid or a gas—passing through the turbine, and interacting with the vanes on the rotor/shaft.
The downhole motor is a kind of downhole dynamic drilling tool that converts the power of drilling mud to a rotation of the drill bit; an application of torque and speed to the drill bit. The advantages of using a downhole motor is that it provides: an increased rate of penetration; better hole deviation control; reduced drill string failure rate.
A downhole motor, mud motor or drilling motor may also be referred to as a Progressive Cavity Positive Displacement Pump that may be disposed on the drillstring to provide additional power to the bit during a drilling process. As described above, the downhole motor uses the drilling fluid to create eccentric motion in the power section of the motor, which is transferred as concentric power to the drill bit. The downhole motor uses different rotor and stator configurations to provide optimum performance for the desired drilling operation; typically the number of lobes and the length of power assembly may be increased to provide greater horsepower. In certain applications, compressed air or other compressed gases may be used to input power to the downhole motor. A rotation of the bit while using a downhole motor may be from about 60 rpm to over 100 rpm.
Downhole motors may comprise a top sub, which connects the downhole motor to the drillstring; the power section, which consists of the rotor and the stator; the transmission section, where the eccentric power from the rotor is transmitted as concentric power to the bit; the bearing assembly which protects the tool from off bottom and on bottom pressures; and the bottom, sub which connects the downhole motor to the bit.
The use of downhole motors is greatly dependent on financial efficiency. In straight vertical holes, the mud motor may be used for increased rate of penetration (ROP), or to minimize erosion and wear on the drill string, since the drill string does not need to be turned as fast. However, the majority of downhole motor use is for directional drilling. Although other methods may be used to steer the drill to directionally drill a borehole, a downhole motor may be the most cost effective method.
In some aspects, the downhole motor may be configured to have include a bend section to provide for directional drilling. Typically, downhole motors can be modified in a range of around zero to four degrees to provide for directional drilling with approximately six increments in deviation per degree of bend. The amount of bend is determined by rate of climb needed to reach the target zone. By using a measurement while drilling (MWD) Tool, a directional driller can steer the bit, which is driven by the downhole motor, to the desired target zone.
The power section of the downhole motor consists of the stator and the rotor. In certain downhole motors, the stator comprises a rubber sleeve on the wall of a steel tube, where the inside of the rubber sleeve defines a spiral structure with a certain geometric parameter. The rotor comprises a shaft, such as a steel shaft, that may be coated with a wear resistant coating, such as chrome and may have a helical profile configured to run/turn/rotate inside the stator.
In the drilling procedure, drilling fluid is pumped downhole through the drill pipe at a given rate and pressure. The downhole motor converts the hydraulic energy of the drilling fluid passing through the power section into mechanical energy, rotation and torque. This mechanical energy is transferred from the downhole motor to the drill bit.
An alternative to using a positive displacement motor is to employ a turbine, in a process often referred to as turbodrilling. In the turbodrill method, power is generated at the bottom of the hole by mud-operated turbines. The turbodrill consists of four basic components: the upper, or thrust, bearing; the turbines, the lower bearing; and the bit. In operation, mud is pumped through the drill pipe, passing through the thrust bearing and into the turbine. In the turbine, stators attached to the body of the tool divert the mud flow onto the rotors attached to the shaft. This causes the shaft, which is connected to the bit, to rotate. The mud passes through a hollow part of the shaft in the lower bearing and through the bit, as in rotary drilling, to remove cuttings, cool the bit, and perform the other functions of the drilling fluid. The capacity of the mud, which is the power source, determines rotational speed.
Multistage high efficiency reaction turbine blades extract hydrolic energy from the flowing mud stream and convert it to mechanical energy (torque and rotation) to drive the drill bit. Each turbine stage consists of a stator, fixed to the body of the tool, and a rotor fixed to the output shaft. These are designed to work in unison, directing and accelerating the mud as it passes through each stage. To achieve the high power and torque levels necessary in performance drilling applications, complete tools are built with approximately 150 sets of identical rotor and stator pairs. To ensure a long life the rotors and stators are manufactured using high performance alloys, which are resistant to both erosion and corrosion.
Similar to a positive displacement motor, the turbodrill generates mechanical power through a pressure drop across the drive system coupled with the fluid flow rate. Generally, the greater the pressure drop capacity of the tool, the greater the potential for delivering mechanical power to the bit. Because the turbodrill power generation system is entirely mechanic, it is capable of supporting an extremely high pressure drop that creates greater mechanical power compared with a mud motor.
In view of their benefits positive displacement motors (PDMs) and turbines are used prolifically in oilfield drilling operations to increase the rotary speed and torque supplied to the bit during drilling.
Although widely used, it is, however, usually unknown exactly the downhole motor is performing, i.e., how much rotary speed and torque is generated etc., by the downhole motor during a downhole drilling operation. In general, the only performance knowledge for the downhole motor is derived guides to the performance of the motor from the motor manufacturer. This manufacturer's guide can take the form of a chart relating the torque and rotation speed of the rotor/turbine as a function of the pressure drop across the motor. However, these charts are generated under surface conditions using an ideal fluid such as water so provide little incite regarding the actual performance of the downhole motor under downhole conditions and being driven by a drilling fluid or the like.
During a downhole drilling operation the downhole conditions give rise to a wide variety of sources of deviation from the manufacturer's performance charts. Such sources of deviation include extremes of temperature and pressure, variation in the properties of the drilling mud, wear of the motor and associated components. All of these can influence the performance of the motor and result in the manufacturer's charts losing accuracy.
Drilling operators in the field are aware of this source of deviation and as a result do not rely on the accuracy of manufacturer's performance charts. As such, drilling operators tend to drill more conservatively than the charts would indicate were possible, to avoid pushing the drill beyond the point of optimal performance and risk stalling the drill.
The effect of this type of conservative operation is that downhole motors and turbines are generally operated sub-optimally, operating below the maximum power output and efficiency possible.
Furthermore, published manufacture curves are often not available for turbines and drillers have only theoretical approximations as to the turbine's speed or power output, making their efficient operation even more problematic.
To a first approximation, the rate of penetration of a drill is maximized when both the weight-on-bit (WOB) and speed of rotation are maximized. However these parameters cannot both be increased indefinitely, as constraints in the system provide a ceiling beyond which drilling cannot proceed. For conventional drilling, a primary constraint is the available power in the top drive, which effectively places a constraint on the combinations of weight-on-bit and rotation speed that are possible.
In many drilling scenarios, the rate of penetration is therefore maximized when operating at the maximum available power of the top drive. Conventional rate of penetration optimization therefore is in determining which combinations of weight-on-bit and rotation speed, given an available power, provide the optimal rate of penetration.
When a mud motor or turbine assisted drilling is employed, the constraint provided by the available power of the top drive may be exceeded, due to the additional hydraulic power provided by the motor or turbine. Thus, greater rates of penetration can be achieved because the important power constraint effectively allows greater weight-on-bit and/or rotation speed.
Patent application WO 2010/043951 discloses a method of optimising the rate of penetration of a drill. The primary parameters employed to predict rate of penetration are the weight applied to the drill bit and the rotation speed of the drill bit.
However, as discussed above, in order to maximize rate of penetration, it is essential to know the maximum available hydraulic power. Attempts to maximize rate of penetration without a knowledge of the available power in a mud motor will result in a stall, which slows down the rate of progress and defeats the object of maximizing rate of penetration.
Thus, even with a knowledge of how to optimize rate of penetration, if a knowledge of the performance of the downhole motor and/or available hydraulic power is not known, not known under operating condition and/or not know in real-time—the drilling system will be operated conservatively and therefore the combinations of weight-on-bit and rotation speed available to a driller (which may be a person, a processor etc.) will provide a reduced rate of penetration than what would be possible if the true performance of the mud motor were known to the operator/driller.